An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole formed in the drilling process will have a diameter generally equal to the diameter or "gage" of the drill bit.
A typical earth-boring bit includes one or more rotatable cutters that perform their cutting function due to the rolling movement of the cutters acting against the formation material. The cutters roll and slide upon the bottom of the borehole as the bit is rotated, the cutters thereby engaging and disintegrating the formation material in its path. The rotatable cutters may be described as generally conical in shape and are therefore sometimes referred to as rolling cones. The borehole is formed as the gouging and scraping or crushing and chipping action of the rotary cones remove chips of formation material which are carried upward and out of the borehole by drilling fluid which is pumped downwardly through the drill pipe and out of the bit.
The earth disintegrating action of the rolling cone cutters is enhanced by providing the cutters with a plurality of cutter elements. Cutter elements are generally of two types: inserts formed of a very hard material, such as tungsten carbide, that are press fit into undersized apertures in the cone surface; or teeth that are milled, cast or otherwise integrally formed from the material of the rolling cone. Bits having tungsten carbide inserts are typically referred to as "TCI" bits, while those having teeth formed from the cone material are known as "steel tooth bits." The cutting surfaces of inserts are, in some instances, coated with a very hard and abrasion resistant coating such as polycrystaline diamond (PCD). Similarly, the teeth of steel tooth bits are many times coated with a hard metal layer generally referred to as "hardfacing." In each instance, the cutter elements on the rotating cutters break up the formation to form new borehole by a combination of gouging and scraping or chipping and crushing.
In oil and gas drilling, the cost of drilling a borehole is proportional to the length of time it takes to drill to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times the drill bit must be changed in order to reach the targeted formation. This is the case because each time the bit is changed, the entire string of drill pipe, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. As is thus obvious, this process, known as a "trip" of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits which will drill faster and longer and which are usable over a wider range of formation hardness.
The length of time that a drill bit may be employed before it must be changed depends upon its rate of penetration ("ROP"), as well as its durability or ability to maintain an acceptable ROP. The form and positioning of the cutter elements (both steel teeth and tungsten carbide inserts) upon the cutters greatly impact bit durability and ROP and thus are critical to the success of a particular bit design.
Bit durability is, in part, measured by a bit's ability to "hold gage," meaning its ability to maintain a full gage borehole diameter over the entire length of the borehole. Gage holding ability is particularly vital in directional drilling applications which have become increasingly important. If gage is not maintained at a relatively constant dimension, it becomes more difficult, and thus more costly, to insert drilling apparatus into the borehole than if the borehole had a constant diameter. For example, when a new, unworn bit is inserted into an undergage borehole, the new bit will be required to ream the undergage hole as it progresses toward the bottom of the borehole. Thus, by the time it reaches the bottom, the bit may have experienced a substantial amount of wear that it would not have experienced had the prior bit been able to maintain full gage. This unnecessary wear will shorten the life of the newly-inserted bit, thus prematurely requiring the time consuming and expensive process of removing the drill string, replacing the worn bit, and reinstalling another new bit downhole.
To assist in maintaining the gage of a borehole, conventional rolling cone bits typically employ a heel row of hard metal inserts on the heel surface of the rolling cone cutters. The heel surface is a generally frustoconical surface and is configured and positioned so as to generally align with and ream the sidewall of the borehole as the bit rotates. The inserts in the heel surface contact the borehole wall with a sliding motion and thus generally may be described as scraping or reaming the borehole sidewall. The heel inserts function primarily to maintain a constant gage and secondarily to prevent the erosion and abrasion of the heel surface of the rolling cone. Excessive wear of the heel inserts leads to an undergage borehole, decreased ROP, increased loading on the other cutter elements on the bit, and may accelerate wear of the cutter bearing and ultimately lead to bit failure.
In addition to the heel row inserts, conventional bits typically include a gage row of cutter elements mounted adjacent to the heel surface but orientated and sized in such a manner so as to cut the corner of the borehole. In this orientation, the gage cutter elements generally are required to cut both the borehole bottom and sidewall. The lower surface of the gage row cutter elements engage the borehole bottom while the radially outermost surface scrapes the sidewall of the borehole. Conventional bits also include a number of additional rows of cutter elements that are located on the cones in rows disposed radially inward from the gage row. These cutter elements are sized and configured for cutting the bottom of the borehole and are typically described as inner row cutter elements.
Differing forces are applied to the cutter elements by the sidewall than the borehole bottom. Thus, requiring gage cutter elements to cut both portions of the borehole compromises the cutter element's design. In general, the cutting action operating on the borehole bottom is typically a crushing or gouging action, while the cutting action operating on the sidewall is a scraping or reaming action. Ideally, a crushing or gouging action requires a tough cutter element, one able to withstand high impacts and compressive loading, while the scraping or reaming action calls for a very hard and wear resistant cutter element. One grade of cemented tungsten carbide or hardfacing cannot optimally perform both of these cutting functions as it cannot be as hard as desired for cutting the sidewall and, at the same time, as tough as desired for cutting the borehole bottom. Similarly, PCD grades differ in hardness and toughness and, although PCD coatings are extremely resistant to wear, they are particularly vulnerable to damage caused by impact loading as typically encountered in bottom hole cutting duty. As a result, compromises have been made in conventional bits such that the gage row cutter elements are not as tough as the inner row of cutter elements because they must, at the same time, be harder, more wear resistant and less aggressively shaped so as to accommodate the scraping action on the sidewall of the borehole.
Attempts have been made in the past to design a bit having an increased ability to hold gage. For example, U.S. Pat. No. 5,353,885 discloses a rolling cone bit in which the heel inserts were moved from a traditional location centrally disposed along the heel surface to a position in which their cutting surface, in rotated profile, overlapped with the cutting profile of the gage row inserts. The heel inserts, due to their positioning, engaged the borehole sidewall at points much lower in the borehole and much sooner on the cutting cycle than in pervious heel row inserts. According to the '885 patent, the "lowering" of the heel inserts spared the gage inserts from having to do a large amount of scraping on the borehole sidewall. This was believed advantageous as it permitted the gage inserts to be made of the same tough grade of tungsten carbide as the inner rows of inserts.
That design, however, presented other compromises. For example, the heel surface of the cone was left unprotected by any hard metal inserts, leading to erosion of the cone and the shirttail of the bit leg after the heel inserts and gage inserts became worn. Erosion of the shirttail portion of the bit leg is especially detrimental as the shirttail performs an important role in protecting the cone seal and bearing from exposure to cuttings and other debris. Additionally, although the sidewall cutting duty was shared between heel inserts and gage inserts in the bit of the '885 patent, the gage inserts were still required to perform a substantial amount of sidewall cutting duty. When gage inserts were made of the same tough tungsten carbide as inner row cutter elements as taught by the '885 patent, they are not as resistant to wear caused by sidewall cutting, and are therefore more susceptible to gage rounding than previous gage row inserts which had been made of a harder more wear resistant material.
Another example of an attempt to increase the gage holding ability of a bit is shown in U.S. Pat. No. 5,351,768. The '768 patent teaches including a scraper insert at the intersection of the heel and gage surfaces of a rolling cone. The scraper insert includes a gage surface and a heel surface which converge to define a relatively sharp cutting edge for engagement with the sidewall of the borehole, the insert also being mounted so as to have a positive rake angle with respect to the sidewall. The scraper insert also is positioned in the cone so that it does not initially engage the borehole sidewall, but only begins to engage formation material after the gage inserts (described therein as "heel" inserts) wear to an appreciable degree. The scraper inserts are thus described as a "secondary" rather than a "primary" cutting structure, and make only incidental contact with the formation material until wear has occurred to the gage inserts. Similarly, the '768 patent teaches that the heel row inserts (described therein as "gage" inserts) do not extend to full gage, so as to maintain a clearance between the heel inserts and the sidewall of the borehole. Again, only when the gage and scraper inserts become severely worn do the heel inserts actively cut sidewall.
Although this arrangement was intended to provide an aggressive cutting structure for increased ROP, the shape and the angle with which the scraper insert attacks the borehole wall make it inherently susceptible to premature wear and damage. With its sharp edge, the scraper inserts will have a high peak contact stress, leading to accelerated wear as compared to a more blunt or rounded cutting surface. Further, the sharp leading edges of the scraper insert are subjected to concentrated forces which may tend to cause premature chipping or breakage, especially when the insert is subjected to side impact loading as may be prevalent in particular formations and in directional drilling. Furthermore, the sharp chisel geometry of the scraper increases the frictional force imposed on the insert, and may lead to intensive localized heat generation at the sharp corners of the cutting surface. Such intense localized heating may lead to heat checking and subsequent cutter element failure.
Additionally, the '768 patent discloses forming one side of the scraper insert from a more wear resistant material than the other. In theory, the less wear resistant surface will wear faster than the other surface, such that the scraper insert will be self sharpening. The '768 patent discloses that the more wear resistant material could be PCD. However, due to the shape of the scraper insert, it is difficult to create a strong bond of PCD at the sharp corners, potentially leading to chipping of the PCD at those sharp corners or radii. Furthermore, the resistance force, a component of the force that is applied tangentially to the cutter element as it engages the formation (in the direction opposite of cutting movement) will attack the discontinuity that exists at the tip of the scraper insert at the intersection of the PCD layer with the tungsten carbide. This substantial force, applied at what amounts to an inherent crack can propagate, causing loss of PCD coating as the frictional force and the resistance force (both being components that together make up the tangential force component) attack the intersection of the tungsten carbide and diamond layer.
Significantly too, the scraper inserts engage the borehole sidewall at a positive rake angle. The shape of scraper insert and its orientation so as to form a positive rake angle creates the potential for, at least initially, a relatively high ROP. At the same time, however, the scraper insert may become quickly dulled or broken due to its aggressive rake angle. Also, because of the orientation of the chisel insert as it sweeps across and engages the borehole wall, the intersection between the PCD layer and carbide is particularly susceptible to attack from the tangential forces imposed on the cutter element. More specifically, the tangential forces are applied at the crest of the chisel insert and are applied in a direction such that the diamond coating is particularly susceptible to chipping and delamination because, at least in certain portions of its cutting cycle, there is not a substantial amount of tungsten carbide substrate to support the diamond coating from the tangential forces that are being applied by the hole wall.
Accordingly, there remains a need in the art for a drill bit and cutting structure that is more durable than those conventionally known and that will yield greater ROP's and an increase in footage drilled while maintaining a full gage borehole. Preferably, the bit and cutting structure would not require the compromises in cutter element toughness, wear resistance and hardness which have plagued conventional bits and thereby limited durability and ROP.